Methods for testing stimulation fluids

ABSTRACT

A method of testing the performance of a stimulation fluid by placing a sample of the stimulation fluid or a precursor thereof into the body of a downhole tool, positioning the tool in juxtaposition with a rock face at a downhole location, forming a sealing contact between the rock face and the tool; and injecting the sample into the rock face while monitoring pressure and/or flow rates during the injection of the sample into and/or production of formation fluid from the rock face to derive a measure of the effectiveness of the stimulation fluid in creating openings in the rock face.

FIELD OF THE INVENTION

The present invention is generally related to hydrocarbon well stimulation, and is more particularly directed to a method for testing stimulation fluid treatments under downhole conditions.

BACKGROUND

Stimulating production through the injection of a stimulation fluid into a subterranean reservoir is well known. Among the most commonly applied methods are hydraulic fracturing and acidizing or a combination of both called acid fracturing or fracture acidizing. In the former case the stimulation fluid is referred to as fracturing fluid, whilst in the latter it is called acidizing fluid or simply acid.

In hydraulic fracturing a fluid is pumped from the surface into a wellbore at a pressure and rate sufficient to open fractures in the rock. During an acidizing treatment the acid or acid mixture (typically including hydrofluoric and hydrochloric acids depending on the rock type) is injected from the surface into the reservoir to dissolve materials that impair well production or to open channels or wormholes in the formation. When combining both methods, it is the role of the acid to etch away from the surface of the fractures to prevent them from closing completely once the pumping pressure is released.

Stimulation fluids and their applications are well established in the oil industry and detailed in a large body of published literature. Among the published documents are the papers by A. N. Martin and Michael J. Economides: Best Practices for Candidate Selection, Design and Evaluation of Hydraulic Fracture Treatments SPE 135669-MS 2010, M. Y. Soliman, Loyd East, and Jody Augustine: Fracturing Design aimed at Enhancing Fracture Complexity SPE 130043-MS 2010 and Phil Rae, Gino di Lullo: Matrix Acid Stimulation—A Review of the State-Of-The-Art SPE 82260-MS 2003.

Another technical area in oil field technology usually considered as unrelated to the production stimulation as described above is the so-called formation sampling. Various techniques for performing formation evaluation (i.e., interrogating and analyzing the surrounding formation regions for the presence of oil and gas) in open, uncased boreholes have been described, for example, in U.S. Pat. Nos. 4,860,581 and 4,936,139, assigned to the assignee of the present invention. An example of this class of tools is Schlumberger's MDT™, a modular dynamic fluid testing tool. Such a tool may include at least one fluid sample bottle, a pump to extract the fluid from the formation or inject fluid into the formation, and a contact pad with a conduit to engage the wall of the borehole. When the device is positioned at a region of interest, the pad is pressed against the borehole wall, making a tight seal for the pumping operation to begin.

To enable the same sampling in cased boreholes, which are lined with a steel tube, sampling tools have been combined with perforating tools. Such cased hole formation sampling tools are described, for example, in the U.S. Pat. No. 7,380,599 to T. Fields et al. and further citing the U.S. Pat. Nos. 5,195,588; 5,692,565; 5,746,279; 5,779,085; 5,687,806; and 6,119,782, all of which are assigned to the assignee of the present invention.

The '588 patent by Dave describes a downhole formation testing tool which can reseal a hole or perforation in a cased borehole wall. The '565 patent by MacDougall et al. describes a downhole tool with a single bit on a flexible shaft for drilling, sampling through, and subsequently sealing multiple holes of a cased borehole. The '279 patent by Havlinek et al. describes an apparatus and method for overcoming bit-life limitations by carrying multiple bits, each of which are employed to drill only one hole. The '806 patent by Salwasser et al. describes a technique for increasing the weight-on-bit delivered by the bit on the flexible shaft by using a hydraulic piston.

Another perforating technique is described in U.S. Pat. No. 6,167,968 assigned to Penetrators Canada. The '968 patent discloses a rather complex perforating system involving the use of a milling bit for drilling steel casing and a rock bit on a flexible shaft for drilling formation and cement.

U.S. Pat. No. 4,339,948 to Hallmark discloses an apparatus and methods for testing, then treating, then testing the same sealed off region of earth formation within a well bore. It employs a sealing pad arrangement carried by the well tool to seal the test region to permit flow of formation fluid from the region. Under certain circumstances, a treating mechanism in the tool injects a treating fluid such as a mud-cleaning acid into the sealed test region of earth formation. A second fluid sample is taken through the sealing pad while the buildup of pressure from the second fluid sample is indicated.

In the U.S. Patent Application Publication 2009/0255669 tools and methods are described for injecting fluid into the formation surrounding wellbore for various purposes such measuring fluid saturations and other formation parameters.

Methods and tools for performing downhole fluid compatibility tests include obtaining a downhole fluid sample, mixing it with a test fluid, and detecting a reaction between the fluids are described in the co-owned U.S. Pat. No. 7,614,294 to P. Hegeman et al. The tool includes a plurality of fluid chambers, a reversible pump and one or more sensors capable of detecting a reaction between the fluids.

In the light of above known art it is seen as an object of the present invention to improve and extend the methods as proposed by Hallmark to perform a downhole testing of stimulation fluids.

SUMMARY OF INVENTION

Hence according to a first aspect of the invention there is provided a method of testing the performance of a stimulation fluid by placing a sample of the stimulation fluid or a precursor thereof into the body of a downhole tool, positioning the tool in juxtaposition with a rock face at a downhole location, forming a sealing contact between the rock face and the tool; and injecting the sample into the rock face while monitoring a pressure is monitored during the injection of the sample into and/or production of formation fluid from the rock to derive a measure of the effectiveness of the stimulation fluid in creating openings in the rock face.

This invention allows evaluation of stimulation fluids at reservoir (downhole) conditions. The invention is particularly useful for evaluation of various fluid formulations used for matrix and hydraulic fracturing for carbonate reservoirs. The method allows the fluid to be tested on several cubic feet of rock volume at reservoir temperature, pressure and saturations. Due to the large rock mass involved, this type of evaluation is extremely difficult and time consuming to conduct in the laboratory.

By measuring pressures or pressures and flow rates during injection various tests can be applied to compare the effectiveness of the stimulation fluid. These tests can be based for example on comparing inflow performance relations or skin effect evaluation.

Existing flow analysis tools can be used to evaluate the clean-up performance of a stimulation fluid after reversing the flow direction to produce fluid from the formation at a point of (prior) injection.

In a preferred embodiment of the invention, several different stimulation fluids or different concentrations of the same stimulation fluid are tested under essential identical downhole conditions. The tests can be performed either by tripping the tool in and out of the well or in a single tool run by moving the tool to a fresh rock face after each injection of a stimulation fluid. For these tests rock of similar or comparable structure has to be selected.

In another variant the fluid is injected at a pressure above the formation fracture pressure to compare the performance of fracture acidizing operations.

These and other aspects of the invention are described in greater detail below making reference to the following drawings.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 shows the operational principles of a formation sampling device;

FIG. 2 illustrates the drilling of a side bore from the main well;

FIGS. 3A-D illustrate steps of a testing method in accordance with the present invention; and

FIGS. 4A-D illustrate further steps of a testing method in accordance with the present invention.

DETAILED DESCRIPTION

In FIG. 1, a well 11 is shown drilled through a formation 10. The well 11 includes an upper cased section 11-1 and a lower openhole section 11-2. The lower openhole section is shown with a layer 12 of formation damaged and invaded through a prior drilling process which left residuals of the drilling fluids in the layer surrounding the well as filter cake.

In this embodiment, a wireline tool 13 as shown in FIG. 1 is lowered into the well 11 using string of drillpipe 14. The drill string 14 is suspended from the surface by means of a drilling rig 15. In the example as illustrated, the wireline tool includes a formation testing device 13-1 combined with a formation drilling device 13-2. Such tools are known and commonly used to collect reservoir fluid samples from cased sections of boreholes. The CHDT™ open hole drilling and testing tool as offered commercially by Schlumberger is an example of such a tool. The connection to the surface is made using a wireline 13-3 partly guided along the drill string 14 (within the cased section) and partly within the drill string (in the open section).

The operation of this combined toolstring in a downhole operation is illustrated schematically in the following FIGS. 2-4

Following the conventional operation mode of the CHDT tool, the body 20 of the tool includes a small formation drill bit 210 mounted on an internal flexible drill string 211. While the tool is kept stationary using the pad 22 and counterbalancing arms (not shown), the flexible drill 210 can be used to drill a small side bore 212 into the formation 10 surrounding the well 11. Once the side bore 212 has reached the desired lateral depth, the drill 210, 211 is withdrawn. This lateral depth can vary depending on the design and purpose of the operation and is typically in the range of about 1 to 30 cm. In the example the side bore 212 is drilled through the damaged layer 12 for about 20 cm to reach parts of the formation not invaded by wellbore fluids.

As shown in FIG. 3A, the pump module 230, a positive displacement pump when using the CHDT tool, is activated after completing the side bore 212 and formation fluid is extracted from the formation 10 through the side bore and the inner flow line 231 of the tool as in conventional sampling. The pad 22 maintains a seal against the well pressure Pw. A pressure sensor 232 is used to monitor the pressure profile during the operations.

The CHDT is used in the example to provide an initial or baseline profile of the productivity of the well. Among the many known indicators or test for the productivity of the well, the inflow performance relation or IPR of pressure versus flow rate is chosen in this specific example.

Controlling the pump rate such that the pressure follows the profile shown in FIG. 3B, where the pressure is lowered stepwise to the maximum drawdown pressure Pdmax of the tool. At each step the corresponding flow rate Q is registered in the tool. After reaching Pdmax the pumping operation is stopped and the gradual pressure build-up as the formation fluid reaches the formation or reservoir pressure Pf is monitored. The asymptotic value of the pressure build-up is taken to represent the formation pressure as in convention well testing (and applying similar corrections for supercharge effects and other perturbations).

It should be understood that the proposed pressure profile as presented in FIG. 3B can be readily replaced by a different sequence. Another suitable profile (not shown) could start with an initial step to a suitable drawdown pressure followed by a shut-in period to establish a reservoir pressure Pf and continue with a stepwise reduction from Pf to the maximum drawdown pressure Pdmax to determine the flow rates Q at various pressures. Such a profile is shown in FIG. 3C illustrating the pressure and flow rate profiles over time.

The measured data can be represented by an initial IPR curve as shown in FIG. 3D. The plot of the pressures P versus flow rates Q is meant to illustrate the type of curves gained from the above steps. Its shape is of course influenced by further formations specific parameters most prominently by the reservoir permeability.

After recording the initial productivity measure for an untreated formation, the tool maintains its position in the well 11. The pump module 230 of the CHDT tool is activated in reverse mode and from an internal reservoir 233 as shown in FIG. 4A a predetermined volume of stimulation fluid is injected through the flow line 231 into the formation 10. A pressure sensor 232 can be used to monitor the pressure profile during the injection and the flow rate of the injected fluid can also be monitored.

The stimulation fluid is the fluid tested for differential production performance over the baseline formation production efficiency as determined above. Provided the internal reservoir 233, pumps 230 and flowline 231 are made of an inert or resistant material, a potentially very large variety of stimulation fluids can be tested under downhole conditions.

Among the stimulation fluids which can be tested using variants of the present invention are either pure acids for various concentrations, for example hydrochloric acid in a range of 5 to 28 wt percent of concentration, or various stimulation fluid compositions such viscoelastic diverting acids, e.g. HCl and a viscoelastic surfactant, self-diverting acids such as HCl and various polymers, or emulsions like HCl and Diesel mixtures, or alcoholic acids, for example HCl and methanol or isopropyl alcohols. Instead of HCl these fluids can also be made with organic acids or chelants. Common organic acids in use are: acetic, formic and citric acid. Common chelants are EDTA (ethylenediamine tetraacetic acid) and DEA (diethanolamine). Mixture of acids can also be used.

Similarly, the performance of diverting agents can be tested either in isolation or as mixtures with acids. Diverting agents can include Foam, benzoic acid flakes, polylactic acid fibers. Using a plurality of internal reservoirs, a sequence of fluids can be injected mirroring the typical sequence of a surface treatment including for example preflush, main stage (HCl or organic acid), main stage (with HF), post flush, and diverting agent. Specifically for the treatment of sandstone formations, this provides the ability to test complex treatment strategies. However using for example specially designed treatments such as offered commercially under the trade name OneStep by Schlumberger, sandstone formations can also be tested using a single internal chamber per treatment test.

Further details of the above treatments can be found in the published literature as cited above and for example in an article by S. Al-Harthy et al.: Options for High Temperature Well Stimulation, published in the Oilfield Review, Winter 2008/9, no. 20(4), pp. 52-62.

Using an internal tool design as described in the above-cited U.S. Pat. No. 7,614,294 to Hegeman et al a plurality of internal chambers and mixing equipment can be applied to prepare at the downhole location a selection of different stimulation fluids for testing.

The result of an effective stimulation fluid is to etch a channel or wormhole into the formation and increasing locally the permeability and thus the productivity of the formation. In FIG. 4B, the tool is shown after the injection of the stimulation fluid. The injection process creates a usually irregularly shaped opening 43 enlarging and extending the existing side bore 212.

After completing the injection, the pumping direction is reversed to produce fluids from the formation as shown in FIG. 4C. As the production stems now from a treated formation, changes in the production flow rates are expected. Following for example again a stepwise change of pressure while measuring the flow rate yields post-treatment IPR curves 41 and 42 as shown in FIG. 4D for two different treatments. The initial IPR curve 31 of FIG. 3D can be compared with the post-treatment curves 41 and 42 at a selected drawdown pressure Pprod, which could be the optimum drawdown pressure. The difference between the initial flow rate Qiprod and the post-treatment flow rates Q1prod and Q2prod at the production pressure, respectively, provide a measure of the effectiveness of the stimulation fluid and the treatment under downhole condition.

The above steps of recording a baseline production profile, conducting a treatment with a stimulation fluid and performing a post-treatment production test can be repeated a number of times under the same downhole conditions and—depending on the tool design and capacity—even within a single trip of the tool. To ensure repeatability it is however important to conduct any series of test on the same or similar formation. This formation has to be unaffected by the previous test.

To overcome this problem, it is proposed to rotate the tool maintain constant depth for example in steps of 180, 120 or 90 degrees to remain within the same formation layer. As an alternative which is easier to perform when the tool is suspended from a wireline or coiled tubing rather than a drill pipe, the tool can be moved to a different depth to face a layer which has been identified from prior logging measurements as being similar to the rock layer used the previous tests.

Further tests related to the treatment efficiency can be performed. A further possible test can be based on a model of the production flow from a wormhole or a similar opening. An model which can be applied in such a manner represents the production flow rate Qt1 as function of the total length H of the opening created and the differential draw down pressure (Pdprod−Pf) assuming an ellipsoidal flow model in which the opening created by the stimulation fluid is represented as half-ellipsoid. Examples of the test can be found for example in R. S. Schechter: Oil Well Stimulation, Prentice Hall Inc., 1991, p. 223, and in C-M. Lea et al.: Simulation of Sandstone Acidizing of a Damaged Perforation SPE Production Engineering, May 1992, pp. 212-218 (SPE 19419), or in Z. Liu and J. Peden: Effects of Perforation Flow Geometry on the Evaluation of Perforation Flow Efficiency, 7^(th) Offshore South East Asia February 1998, pp. 322-330 (SPE 17672). In these models the flow rate is linked to the differential pressure and the radius and length of the opening as Qt1prod=2pikH/mu*((Pdprod−Pf)/G) where G is a geometrical factor related to the width of the opening or similar equations.

Applying this model the depth or length H of an etched opening such as wormhole 43 of FIG. 4B can be approximated.

A further test can be performed during the flow back of fluid from the formation into the tool after the injection of the stimulation fluid, i.e., in particular during the phase referred to as “clean-up” in conventional stimulation treatments. In this phase, the stimulation fluid or any its mobile reaction products will be pumped back into the tool before the actual formation fluid enters the tool body. This sequence of flows allows for a more detailed analysis of important aspects of the stimulation fluid such as clean-up efficiency.

Typically, the above mentioned commercially available formation testing devices carry integrated into their inner flow line an optical fluid analyzer shown for example as analyzer 44 in FIG. 4C. As mentioned above, the FIG. 4C illustrates the stage where the flow direction is reversed and the stimulation fluid is removed from the opening 43 in the clean-up process. The optical fluid analyzer 44 can be applied to monitor the flow for components of the stimulation fluid. Thus the clean-up time can be monitored as the time at which any mobile phase of the stimulation fluid is removed from the formation and formation fluid enters the tool.

The clean-up time, the flow rates during and after clean-up and analysis of the stimulation fluid components during the clean-up provide further indicators for the efficiency of a stimulation fluid. Any tendency of the tested stimulation fluid to permanently block the formation or reduce permeability can be detected.

An alternative to or extension of the above tests for evaluating the effectiveness of the stimulation treatment includes the measurements of injection rate vs. pressure, using for example a time evolution of the skin effect to interpret the effectiveness of the treatment. Such test methods are known from well testing and a widely used test method in this field is known as Economides-Provost test. Details of this test are described in L. P. Provost and M. J. Economides: Applications of Real-Time Matrix Acidizing Evaluation Method, SPE Production Engineering, Nov 198, pp. 401-407 (SPE 17156).

Moreover, while the preferred embodiments are described in connection with various illustrative processes, one skilled in the art will recognize that the system may be embodied using a variety of specific procedures and equipment. Accordingly, the invention should not be viewed as limited except by the scope of the appended claims. 

What is claimed is:
 1. A method of testing the performance of a stimulation fluid, comprising the steps of placing a sample of said stimulation fluid or a precursor thereof into the body of a downhole tool; positioning said tool in juxtaposition with a rock face at a downhole location; forming a sealing contact between said rock face and the tool; and injecting said sample into said rock face while monitoring pressure during the injection of the sample to derive a measure of the effectiveness of said stimulation fluid in creating openings in said rock face.
 2. A method in accordance with claim 1, wherein prior to the injection a hole is drilled into the rock face through which the sample is injected.
 3. A method in accordance with claim 2, wherein the rock face is completed as open hole.
 4. A method in accordance with claim 1, wherein the pressure is monitored essentially continuous to derive an injection profile.
 5. A method in accordance with claim 1, wherein flow rates and pressures are monitored during injection into and/or production of fluids from the rock face.
 6. A method in accordance with claim 5, wherein IPR curves are determined to evaluate the effectiveness of the stimulation fluid.
 7. A method in accordance with claim 5, wherein time evolution of the skin effect is determined to evaluate the effectiveness of the stimulation fluid.
 8. A method in accordance with claim 5, wherein a Provost-Economides type of test is used to evaluate the effectiveness of the stimulation fluid.
 9. A method in accordance with claim 5, wherein the flow rate from an etched hole at a given production pressure differential is used to determine a geometric parameter representative of the size of said etched hole.
 10. A method in accordance with claim 1, further comprising the step of reversing the flow to produce fluid from the formation after the injection and analyzing components of reversed flow.
 11. A method in accordance with claim 10, wherein the reversed flow is monitored for the presence of the stimulation fluid or reaction products of the stimulation fluid.
 12. A method in accordance with claim 10, wherein the reversed flow is monitored for a transition point indicating the onset production of formation fluid from the formation.
 13. A method in accordance with claim 1, wherein the injection pressure is selected to be above the rock fracture pressure.
 14. A method in accordance with claim 1, wherein multiple positions facing a identical or similar rock type are identified and the tool is positioned successively at said positions to allow the injection of several samples.
 15. A method in accordance with claim 1, wherein multiple downhole locations each facing a identical or similar rock type are identified and the tool is positioned successively at said locations to allow the injection of several samples during a single downhole tool trip. 